One hears such mantras every day in the power industry, but one interesting thing about SMUD is, the organization actually used customer data and face-to-face community meetings to understand their customers' interests. Then, SMUD realigned its organization to address those interests. With that reorganization done, SMUD set about tackling its grid modernization efforts—and made its technology choices—accordingly.

That's about as close as you get to moving from data to value, and it's about as fundamental a connection as can be made, given the far-reaching changes driven by customer interests.

Having taken its customers' concerns to heart, the next step in strategic thinking at SMUD was to ensure it was looking at the complete picture and understanding "drivers and linkages," in Lau's words.

"We've taken a holistic approach to what implementing a smart grid means to Sacramento," Lau told me recently.

SMUD determined what business intelligence (BI) would serve customers' interests first, then it looked at the technology that would produce the BI.

"We asked ourselves, 'What processes deliver the value we seek?'" Lau said. "And then, 'what systems support those processes?' We organized SMUD along those lines, breaking down silos as it went.

"It all began with customer-facing realignment processes to create the shortest distance between two points," Lau said.

Those changes prepared the utility to launch a $308 million smart grid project (with a $127 million stimulus grant) that is addressing advanced metering infrastructure (AMI), distribution automation and a variety of customer facing programs. Once SMUD applied customer segmentation principles to its customer base, it proceeded with new programs such as time-of-use rates and new credit/collection policies that limit arrears and keep customers satisfied.

Underneath the warm and fuzzy language, SMUD has hard and fast metrics to meet as it goes about its technology roadmap. For its AMI project, the cost savings from more efficient operations must pay for the capital cost of the project—with no added financial burden on customers. The distribution automation project has a goal of improving outage restoration by reducing the frequency and duration of outages by 25 percent.

"It takes discipline," Lau acknowledged.

But the incentive is to keep customers registering 95 percent satisfaction in J.D. Power & Associates surveys, as they have in the past.

Jeff Myerson, service area director and subject matter expert for CenterPoint Energy's Intelligent Grid project, has a slightly different story to tell, but it's also a narrative about using data to inform business decisions that ultimately benefit the customer.

"We put our customers first," Myerson told me recently. "And to do that we deliver improved reliability, give them more management control over their energy use and keep them better informed of utility activities."

CenterPoint Energy has deployed 2.1 million meters in its 2.2 million meter service territory in its advanced metering infrastructure project, which includes several components.

"Our project includes not only the meters, but the communication infrastructure, the server environment, data collection engine and meter data management systems, plus monitoring and diagnostic capabilities," Myerson told me. "Overall, it is a $640 million project that will be complete by the middle of this year."

In addition, CenterPoint has begun work on its "Intelligent Grid" infrastructure project, which includes digital substation monitors, remote terminal units (RTUs), smart switches that monitor power flow and detect faults, plus a management system that overlays all that and incorporates outage management, distribution management and distribution SCADA systems.

That project is planned to initially cover about 15 percent of CenterPoint's grid. The first phase is underway, with monitors at seven of 29 substations and 200 switches already installed.

With its AMI project largely completed, CenterPoint has seen Big Data begin to flow, which has enabled automated processes such as remote connect/disconnect and speeded up service orders that have drastically reduced truck rolls. So far, about 2.5 million field visits have been eliminated by the system.

In CenterPoint's case, that's actually a direct customer benefit, because the utility used to bill customers for a service order—such as service connection or disconnection—about $16 for the visit, which might take hours after the request to complete. Those services now are free and take about 30 minutes. Billing reliability also is up; formerly the rate of estimation was about 1.5 percent, today it is less than 0.1 percent.

"One of the things I'd like to talk about at EBLF is the 'data explosion,'" Myerson said. "We used to collect 2.2 million meter reads a month. We now collect 6.6 billion data points per month. I'd call that an explosion. So we've run into some serious pressure regarding the amount of data that we're collecting. That's pressure on our technology and our business processes."

Getting full business value out of that data stream will take time, Myerson said. One way is to improve algorithms that receive meter outage detection data over time, so that analyses that today require manual investigation can be automated. That means bringing several disparate strands of data together to understand why a meter is not communicating or has been removed. Did a CenterPoint technician remove a meter or has it been tampered with? As algorithms are set up and honed with real life data that correlate with known causes, automation will replace staff time in such matters.

A single meter not communicating after an electric outage could simply indicate a meter or power problem at one residence. But a cluster of them probably indicates a nested outage and the data should indicate what sort of problem has arisen.

"Our goal is to send the right crew with the right equipment to the right location," Myerson said.

That "tuning" of algorithms is expected to be an ongoing process, but significant optimization is likely within two to four years, Myerson said.

"We'll keep enriching the data," he said. "Meter data is just one part of the story. We'll add weather data, historical use data, etc., to get the most accurate picture of what's taking place in the field."

One big driver of these automated systems was 2008's Hurricane Ike, which led to a Houston-based task force that focused on measures that could lead to quicker service restoration. The work at CenterPoint will continue for a decade, but providing individual customers with estimated restoration times for their home or business will reach customers sometime next year, in the format they prefer (text, email, phone call, etc.).

And that reflects the guiding principle that CenterPoint has embraced: put the customer first by delivering greater reliability and providing the tools for them to manage their energy use.

Readers, if you're in Washington, D.C., consider attending the EnergyBiz Leadership Forum, March 19-21, which is run by EnergyCentral, also the parent of Intelligent Utility. You'll learn much more about what SMUD and CenterPoint are doing and have access to the power industry's leading thinkers and doers. Click on the link for details.

26,414 Members

Like the rest of the world, utilities are becoming more and more digital. This affects almost every aspect of a utility – including customer service, generation, transmission, distribution and energy management. While this is an exciting time, it is also confusing. The mission of our community is to bring together utility folks who are in the thick of the digital utility transformation.

Sponsors

Ciena is a network strategy and technology company known for its commitment to customer success. With nearly 25 years of industry leadership, we support more than 1,300 of the world’s largest, most reliable networks.